ML20337A037

Issuance of Amendment No. 353 Regarding Steam Generator Tube Inspection Frequency

ML20337A037
Person / Time
Site:	Sequoyah
Issue date:	02/01/2021
From:	Michael Wentzel Plant Licensing Branch II
To:	Jim Barstow Tennessee Valley Authority
Wentzel M
References
EPID L-2020-LLA-0030
Download: ML20337A037 (20)

Text

February 1, 2021 Mr. James Barstow Vice President, Nuclear Regulatory Affairs and Support Services Tennessee Valley Authority 1101 Market Street, LP 4A-C Chattanooga, TN 37402-2801

SUBJECT:

SEQUOYAH NUCLEAR PLANT, UNIT 1 - ISSUANCE OF AMENDMENT NO. 353 REGARDING STEAM GENERATOR TUBE INSPECTION FREQUENCY (EPID L-2020-LLA-0030)

Dear Mr. Barstow:

The U.S. Nuclear Regulatory Commission (Commission) has issued the enclosed Amendment No. 353 to Renewed Facility Operating License No. DPR-77 for the Sequoyah Nuclear Plant, Unit 1. This amendment is in response to your application dated February 24, 2020, as supplemented by letter dated September 23, 2020.

The amendment revises Technical Specification 5.5.7, Steam Generator (SG) Program, and Technical Specification 5.6.6, Steam Generator Tube Inspection Report, to revise the required SG tube inspection frequency from every 72 effective full power months to every 96 effective full power months.

A copy of our related Safety Evaluation is also enclosed. A Notice of Issuance will be included in the Commissions monthly Federal Register notice.

Sincerely,

/RA/

Michael J. Wentzel, Project Manager Plant Licensing Branch II-2 Division of Operating Reactor Licensing Office of Nuclear Reactor Regulation Docket No. 50-327

Enclosures:

1. Amendment No. 353 to DPR-77

2. Safety Evaluation cc: Listserv

TENNESSEE VALLEY AUTHORITY DOCKET NO. 50-327 SEQUOYAH NUCLEAR PLANT, UNIT 1 AMENDMENT TO RENEWED FACILITY OPERATING LICENSE Amendment No. 353 Renewed License No. DPR-77

1.

The U.S. Nuclear Regulatory Commission (the Commission) has found that:

A.

The application for amendment by Tennessee Valley Authority (the licensee) dated February 24, 2020, as supplemented by letter dated September 23, 2020, complies with the standards and requirements of the Atomic Energy Act of 1954, as amended (the Act), and the Commissions rules and regulations set forth in 10 CFR Chapter I; B.

The facility will operate in conformity with the application, the provisions of the Act, and the rules and regulations of the Commission; C.

There is reasonable assurance (i) that the activities authorized by this amendment can be conducted without endangering the health and safety of the public, and (ii) that such activities will be conducted in compliance with the Commissions regulations; D.

The issuance of this amendment will not be inimical to the common defense and security or to the health and safety of the public; and E.

The issuance of this amendment is in accordance with 10 CFR Part 51 of the Commissions regulations and all applicable requirements have been satisfied.

2.

Accordingly, the license is amended by changes to the Technical Specifications as indicated in the attachment to this license amendment and paragraph 2.C.(2) of Renewed Facility Operating License No. DPR-77 is hereby amended to read as follows:

(2)

Technical Specifications The Technical Specifications contained in Appendices A and B, as revised through Amendment No. 353, are hereby incorporated in the renewed license. The licensee shall operate the facility in accordance with the Technical Specifications.

3.

This license amendment is effective as of its date of issuance, to be implemented within 30 days after issuance.

FOR THE NUCLEAR REGULATORY COMMISSION Undine S. Shoop, Chief Plant Licensing Branch II-2 Division of Operating Reactor Licensing Office of Nuclear Reactor Regulation

Attachment:

Changes to the Renewed Facility Operating License and Technical Specifications Date of Issuance: February 1, 2021 Undine S.

Shoop Digitally signed by Undine S. Shoop Date: 2021.02.01 13:51:10 -05'00'

ATTACHMENT TO LICENSE AMENDMENT NO. 353 SEQUOYAH NUCLEAR PLANT, UNIT 1 RENEWED FACILITY OPERATING LICENSE NO. DPR-77 DOCKET NO. 50-327 Replace page 3 of the Renewed Facility Operating License with the attached page 3.

Replace the following pages of the Appendix A Technical Specifications with the attached revised pages. The revised pages are identified by amendment number and contain marginal lines indicating the areas of change.

REMOVE INSERT 5.5-6 5.5-6 5.5-7 5.5-7 5.6-5 5.6-5 Amendment No. 353 Renewed License No. DPR-77 (3)

Pursuant to the Act and 10 CFR Parts 30, 40 and 70, to receive, possess, and use at any time any byproduct, source and special nuclear material as sealed neutron sources for reactor startup, sealed sources for reactor instrumentation and radiation monitoring equipment calibration, and as fission detectors in amounts as required; (4)

Pursuant to the Act and 10 CFR Parts 30, 40 and 70, to receive, possess, and use in amounts as required any byproduct, source or special nuclear material without restriction to chemical or physical form, for sample analysis or instrument calibration or associated with radioactive apparatus or components; and (5)

Pursuant to the Act and 10 CFR Parts 30, 40 and 70, to possess, but not separate, such byproduct and special nuclear materials as may be produced by the operation of the Sequoyah and Watts Bar Unit 1 Nuclear Plants.

C.

This renewed license shall be deemed to contain and is subject to the conditions specified in the Commissions regulations set forth in 10 CFR Chapter I and is subject to all applicable provisions of the Act and to the rules, regulations, and orders of the Commission now or hereafter in effect; and is subject to the additional conditions specified or incorporated below:

(1)

Maximum Power Level The Tennessee Valley Authority is authorized to operate the facility at reactor core power levels not in excess of 3455 megawatts thermal.

(2)

Technical Specifications The Technical Specifications contained in Appendices A and B, as revised through Amendment No. 353 are hereby incorporated into the renewed license. The licensee shall operate the facility in accordance with the Technical Specifications.

(3)

Initial Test Program The Tennessee Valley Authority shall conduct the post-fuel-loading initial test program (set forth in Section 14 of Tennessee Valley Authoritys Final Safety Analysis Report, as amended), without making any major modifications of this program unless modifications have been identified and have received prior NRC approval. Major modifications are defined as:

a.

Elimination of any test identified in Section 14 of TVAs Final Safety Analysis Report as amended as being essential;

b.

Modification of test objectives, methods, or acceptance criteria for any test identified in Section 14 of TVAs Final Safety Analysis Report as amended as being essential;

Programs and Manuals 5.5 5.5 Programs and Manuals SEQUOYAH - UNIT 1 5.5-6 Amendment 334, 353 5.5.7 Steam Generator (SG) Program (continued) 2.

Accident induced leakage performance criterion: The primary to secondary accident induced leakage rate for any design basis accident, other than a SG tube rupture, shall not exceed the leakage rate assumed in the accident analysis in terms of total leakage rate for all SGs and leakage rate for an individual SG. Leakage is not to exceed 1 gpm per SG.

3.

The operational LEAKAGE performance criterion is specified in LCO 3.4.13, "RCS Operational LEAKAGE."

c.

Provisions for SG tube plugging criteria. Tubes found by inservice inspection to contain flaws with a depth equal to or exceeding 40% of the nominal tube wall thickness shall be plugged.

d.

Provisions for SG tube inspections. Periodic SG tube inspections shall be performed. The number and portions of the tubes inspected and methods of inspection shall be performed with the objective of detecting flaws of any type (e.g., volumetric flaws, axial and circumferential cracks) that may be present along the length of the tube, from the tube-to-tubesheet weld at the tube inlet to the tube-to-tubesheet weld at the tube outlet, and that may satisfy the applicable tube plugging criteria. The tube-to-tubesheet weld is not part of the tube. In addition to meeting the requirements of d.1, d.2, and d.3 below, the inspection scope, inspection methods, and inspection intervals shall be such as to ensure that SG tube integrity is maintained until the next SG inspection. A degradation assessment shall be performed to determine the type and location of flaws to which the tubes may be susceptible and, based on this assessment, to determine which inspection methods need to be employed and at what locations.

1.

Inspect 100% of the tubes in each SG during the first refueling outage following SG installation.

2.

After the first refueling outage following SG installation, inspect each SG at least every 96 effective full power months. Tube inspections shall be performed using equivalent to or better than array probe technology. For regions where a tube inspection with array probe technology is not possible (such as due to dimensional constraints or tube specific conditions), the tube inspection techniques applied shall be capable of detecting all forms of existing and potential degradation in that region. In addition, the minimum number of tubes inspected at each scheduled inspection shall be the number of tubes in all SGs divided by the number of SG inspection outages scheduled in each inspection period as defined in a and b below. If a degradation assessment indicates the potential for a type of degradation to occur at a location not previously inspected with a technique capable of detecting this type of degradation at this location and that may satisfy

Programs and Manuals 5.5 5.5 Programs and Manuals SEQUOYAH - UNIT 1 5.5-7 Amendment 334, 353 5.5.7 Steam Generator (SG) Program (continued) the applicable tube plugging criteria, the minimum number of locations inspected with such a capable inspection technique during the remainder of the inspection period may be prorated. The fraction of locations to be inspected for this potential type of degradation at this location at the end of the inspection period shall be no less than the ratio of the number of times the SG is scheduled to be inspected in the inspection period after the determination that a new form of degradation could potentially be occurring at this location divided by the total number of times the SG is scheduled to be inspected in the inspection period. Each inspection period defined below may be extended up to 3 effective full power months to include a SG inspection outage in an inspection period and the subsequent inspection period begins at the conclusion of the included SG inspection outage.

a)

After the first refueling outage following SG installation, inspect 100% of the tubes during the next 144 effective full power months.

This constitutes the first inspection period; b)

During the next 96 effective full power months, inspect 100% of the tubes. This constitutes the second and subsequent inspection periods.

3.

If crack indications are found in any SG tube, then the next inspection for each affected and potentially affected SG for the degradation mechanism that caused the crack indication shall not exceed 24 effective full power months or one refueling outage (whichever results in more frequent inspections). If definitive information, such as from examination of a pulled tube, diagnostic non-destructive testing, or engineering evaluation indicates that a crack-like indication is not associated with a crack(s), then the indication need not be treated as a crack.

e.

Provisions for monitoring operational primary to secondary LEAKAGE.

Reporting Requirements 5.6 SEQUOYAH - UNIT 1 5.6-5 Amendment 334, 353 5.6 Reporting Requirements 5.6.6 Steam Generator Tube Inspection Report A report shall be submitted within 180 days after the initial entry into MODE 4 following completion of an inspection performed in accordance with the Specification 5.5.7, "Steam Generator (SG) Program." The report shall include:

a.

The scope of inspections performed on each SG; b.

Active degradation mechanisms found; c.

Nondestructive examination techniques utilized for each degradation mechanism; d.

Location, orientation (if linear), and measured sizes (if available) of service induced indications; e.

Number of tubes plugged during the inspection outage for each active degradation mechanism; f.

Total number and percentage of tubes plugged to date; g.

The results of condition monitoring, including the results of tube pulls and in-situ testing; and h.

The effective plugging percentage for all plugging in each SG.

i.

Discuss trending of tube degradation over the inspection interval and provide comparison of the prior operational assessment degradation projections to the as-found condition.

SAFETY EVALUATION BY THE OFFICE OF NUCLEAR REACTOR REGULATION RELATED TO AMENDMENT NO. 353 TO RENEWED FACILITY OPERATING LICENSE NO. DPR-77 TENNESSEE VALLEY AUTHORITY SEQUOYAH NUCLEAR PLANT, UNIT 1 DOCKET NO. 50-327

1.0 INTRODUCTION

By application dated February 24, 2020 (Reference 1), as supplemented by letter dated September 23, 2020 (Reference 2), the Tennessee Valley Authority (TVA; the licensee) requested an amendment to the Technical Specifications (TSs) for Sequoyah Nuclear Plant (Sequoyah), Unit 1. The requested changes would revise TS 5.5.7, Steam Generator (SG)

Program, and TS 5.6.6, Steam Generator Tube Inspection Report, to revise the required SG tube inspection frequency from every 72 effective full power months (EFPM) to every 96 EFPM.

The supplement dated September 23, 2020, provided additional information that clarified the application, did not expand the scope of the application as originally noticed, and did not change the staffs initial proposed no significant hazards consideration determination as published in the Federal Register on April 7, 2020 (85 FR 19511).

2.0 REGULATORY EVALUATION

2.1

System Description

The tubes within an SG function as an integral part of the reactor coolant pressure boundary and, in addition, isolate fission products in the primary coolant from the secondary coolant and the environment. For the purposes of this safety evaluation, SG tube integrity means the tubes are capable of performing this safety function in accordance with the plant design and licensing basis.

2.1.1 Steam Generator Design Sequoyah, Unit 1, has four Westinghouse Model 57AG replacement SGs that were installed in 2003. Each SG contains 4,983 thermally treated Alloy 690 tubes, which have a nominal outside diameter of 0.75 inches and a nominal wall thickness of 0.043 inches. The tubes were hydraulically expanded into the tubesheet, and the straight portion of the tubes are supported by seven Type 409 stainless steel, advanced tube support grids. The U-bend portions of the tubes are supported by anti-vibration bars that are composed of ventilated flat bar support trees with varying numbers of diagonal and vertical straps, depending on tube location.

2.1.2 Operating Experience The only degradation mechanisms detected in the Sequoyah, Unit 1, replacement SGs are tube wear from interaction with anti-vibration bars and advanced tube support grids. Since being placed in-service in 2003, only tube wear from interaction with anti-vibration bars has resulted in tubes being removed from service (i.e., plugged). Table 1 contains the plugging summary for the Sequoyah, Unit 1, SGs. An operating experience review of degradation noted during inspections is provided below.

Tube Wear During fabrication of the Sequoyah, Unit 1, SGs, 18 tubes were preventatively plugged due to broken U-bend support lock bars at eight separate locations on the edge of the tube bundle.

Loads resulting from vessel rotation during fabrication caused the lock bars to break or crack.

Associated loose parts were removed, and the lock bars themselves were stabilized by welding.

Two additional tubes were plugged during the preservice inspection (one due to wear near the lock bar repair activities and one due to a restricted tube) for a total of 20 plugged tubes. The licensee stated that since the replacement SGs were installed, no operational wear associated with this fabrication issue has been observed.

The first in-service inspection after SG installation occurred in 2004 during Refueling Outage 13 (1R13) and included a full-length bobbin probe inspection of all tubes, plus a rotating pancake coil inspection of signals that were not resolved by review of the bobbin inspection data. The largest indication measured was a 17 percent through-wall anti-vibration bar wear indication. The licensee plugged 11 tubes with anti-vibration bar wear indications.

The second in-service SG inspection occurred in Fall 2007 during 1R15 and included 54 percent of the in-service tubes with a bobbin probe and rotating pancake coil for signals unresolved by bobbin data review. The largest indication measured was a 16 percent through-wall anti-vibration bar wear indication. No tubes were plugged during the outage.

The third SG inspections were in Spring 2012 during 1R18. These SG inspections included 46 percent of the in-service tubes and an inspection program with the combination bobbin and array coil probe for regions considered most susceptible to foreign object wear near the top-of-tubesheet, on both the hot and cold leg sides. A special interest rotating pancake coil program was performed for signals that could not be resolved by bobbin or array coil data review. Tube wear at the advanced tube support grids was detected for the first time during 1R18 but did not result in any tube plugging. The two tubes with the two deepest anti-vibration bar wear indications (38 and 29 percent through-wall) were plugged (one of the tubes was stabilized).

Table 1: Sequoyah Unit 1 SG Tube Plugging Degradation Mechanism SG1 SG2 SG3 SG4 Total Pre-Service 4

6 5

5 20 Anti-Vibration Bar Wear 12 0

2 0

14 Advanced Tube Support Grid Wear 0

0 0

0 0

Total 16 6

7 5

34 Percentage 0.32%

0.12%

0.14%

0.10%

0.17%

The fourth (and most recent) in-service SG inspections were in Fall 2016 during 1R21 and included a 100 percent combination bobbin and array probe inspection for the full length of all tubes in rows 5 and above. Due to the dimensional constraints of the U-bend sections of the tubes in rows 1 through 4, these tubes were inspected with a singular bobbin probe from the first advanced tube support grid on the hot-leg side to the first advanced tube support grid on the cold-leg side, while the straight section from the tube end to the first advanced tube support grid was inspected with the combined bobbin and array coil probe, on both hot and cold legs.

Tube wear from anti-vibration bars and advanced tube support grids were the only degradation mechanisms detected during 1R21, and one tube with a 36 percent through-wall anti-vibration bar wear indication was the only tube plugged during the outage. Additional information about the four in-service SG inspections is available in the SG Tube Inspection Reports (References 3 through 8).

Corrosion Degradation Sequoyah, Unit 1, has not reported any indications of corrosion degradation, such as stress corrosion cracking, and to date, the NRC staff is unaware of any corrosion degradation in operating SGs with Alloy 690TT tubing. Regardless of this corrosion degradation operating experience, the Sequoyah, Unit 1, TSs require that a degradation assessment be performed prior to each SG inspection, to determine the type and location of flaws to which the tubes may be susceptible and, based on this assessment, to determine which inspection methods need to be employed and at what locations. Therefore, the SG inspection strategy for Sequoyah, Unit 1 includes inspections with specialized eddy current probes for potential corrosion degradation mechanisms.

Secondary Side Inspections The secondary-side activities for the Sequoyah, Unit 1, SGs in 1R13 included top-of-tubesheet sludge lancing and foreign object search and retrieval, in the four SGs. Some minute magnetic debris was identified and removed from SGs 1, 3, and 4.

During 1R15, TVA performed steam drum inspections in each SG without any findings. A foreign object search and retrieval inspection was performed after sludge lancing on each SG tubesheet annulus and no-tube lane regions; no loose parts or foreign objects were identified.

The secondary-side activities also included an in-bundle visual examination of two cold-leg and hot-leg columns in SG 4, again with no findings.

During 1R18, steam drum and tubesheet region inspections were performed in all four SGs. A small piece of screen type material was found and removed from one of the SG 1 feedwater spray nozzles. The tubesheet inspections revealed four foreign objects, all of which were removed.

During 1R21, secondary side visual inspections were performed at the top of the tubesheet to detect foreign objects, assess hard deposit buildup, and to determine tubesheet cleaning effectiveness in all four SGs. The foreign object search and retrieval inspections of all four SGs included visual examination of periphery tubes on the hot-leg and cold-leg annulus and center no-tube lane. Fifteen foreign objects were removed from the tubesheet region, and 23 objects remain on the secondary side among the four SGs. The foreign objects remaining were small pieces of gasket, wires, bristles, and graphite. These foreign objects were characterized and analyzed to demonstrate acceptability of continued operation without exceeding the tube integrity performance criteria.

2.1.3 Technical Specification Requirements TS 3.4.17, Steam Generator (SG) Tube Integrity, requires SG tube integrity to be maintained, and requires all SG tubes satisfying the tube plugging criteria to be plugged in accordance with the Steam Generator Program. Surveillance Requirement 3.4.17.1 requires tube integrity to be verified according to the Steam Generator Program.

For Sequoyah, Unit 1, the Steam Generator Program requirements for performing SG tube inspections and plugging are in TS 5.5.7, while the requirements for reporting the SG tube inspections and plugging are in TS 5.6.6.

For Sequoyah, Unit 1, SG tube integrity is maintained by meeting the performance criteria specified in TS 5.5.7.b for structural and leakage integrity, consistent with the plant design and licensing basis. TS 5.5.7.a requires that a condition monitoring assessment be performed during each outage in which the SG tubes are inspected, to confirm that the performance criteria are being met. TS 5.5.7.d includes provisions regarding the scope, frequency, and methods of SG tube inspections. These provisions require that the inspections be performed with the objective of detecting flaws of any type that may be present along the length of a tube and that may satisfy the applicable tube plugging criteria. The applicable tube plugging criteria, specified in TS 5.5.7.c, are that tubes found during in-service inspection to contain flaws with a depth equal to or exceeding 40 percent of the nominal wall thickness shall be plugged.

Sequoyah Unit 1, TS 3.4.13 includes a limit on operational primary-to-secondary leakage, beyond which the plant must be promptly shutdown. Should a flaw exceeding the tube plugging limit not be detected during the periodic tube surveillance required by the plant TS, the operational leakage limit provides added assurance of timely plant shutdown before tube structural and leakage integrity are impaired, consistent with the design and licensing bases.

2.2 Regulatory Requirements and Guidance The NRC staff reviewed the licensees application to determine whether (1) there is reasonable assurance that the health and safety of the public will not be endangered by operation in the proposed manner, (2) activities proposed will be conducted in compliance with the Commissions regulations, and (3) the issuance of the amendments will not be inimical to the common defense and security or the health and safety of the public. The NRC staff considered the following regulatory requirements during its review of the proposed changes.

Section 50.36, Technical specifications, of Title 10 of the Code of Federal Regulations (10 CFR) establishes the regulatory requirements related to the content of TSs.

Paragraph 50.36(a)(1) of 10 CFR requires an application for a reactor operating license to include proposed TSs. A summary statement of the bases or reasons for such specifications, other than those covering administrative controls, shall also be included in the application, but shall not become part of the TSs.

Pursuant to 10 CFR 50.36(c), TSs for operating reactors are required, in part, to include items in the following five specific categories: (1) safety limits, limiting safety system settings, and limiting control settings; (2) limiting conditions for operation; (3) surveillance requirements; (4) design features; and (5) administrative controls.

Paragraph 50.36(c)(5) of 10 CFR states that administrative controls are the provisions relating to organization and management, procedures, recordkeeping, review and audit, and reporting necessary to assure operation of the facility in a safe manner.

As part of a plants licensing basis, applicants for pressurized-water reactor licenses are required to analyze the consequences of postulated design-basis accidents, such as a SG tube rupture and a steam line break. These analyses consider primary-to-secondary leakage that may occur during these events and must show that the radiological consequences do not exceed the applicable limits of 10 CFR 50.67 or 10 CFR 100.11 for offsite doses; General Design Criterion 19 of 10 CFR Part 50, Appendix A for control room operator doses (or some fraction thereof as appropriate to the accident); or the NRC-approved licensing basis (e.g., a small fraction of these limits). No accident analyses for Sequoyah, Unit 1, are being changed because of the proposed amendment and, thus, no radiological consequences of any accident analysis are being changed. The proposed changes maintain the accident analyses and consequences that the NRC has reviewed and approved for the postulated design-basis accidents for SG tubes.

2.3 Proposed Changes The licensee proposed to make the following revisions to TSs 5.5.7 and 5.6.6 (deletions shown in stricken text and additions underlined):

TS 5.5.7.d.2

2.

After the first refueling outage following SG installation, inspect each SG at least every 72 96 effective full power months. Tube inspections shall be performed using equivalent to or better than array probe technology. For regions where a tube inspection with array probe technology is not possible (such as due to dimensional constraints or tube specific conditions), the tube inspection techniques applied shall be capable of detecting all forms of existing and potential degradation in that region. or at least every third refueling outage (whichever results in more frequent inspections). In addition, the minimum number of tubes inspected at each scheduled inspection shall be the number of tubes in all SGs divided by the number of SG inspection outages scheduled in each inspection period as defined in a and, b, c, and d below. If a degradation assessment indicates the potential for a type of degradation to occur at a location not previously inspected with a technique capable of detecting this type of degradation at this location and that may satisfy the applicable tube plugging criteria, the minimum number of locations inspected with such a capable inspection technique during the remainder of the inspection period may be prorated. The fraction of locations to be inspected for this potential type of degradation at this location at the end of the inspection period shall be no less than the ratio of the number of times the SG is scheduled to be inspected in the inspection period after the determination that a new form of degradation could potentially be occurring at this location divided by the total number of times the SG is scheduled to be inspected in the inspection period. Each inspection period defined below may be extended up to 3 effective full power months to include a SG inspection outage in an inspection period and the subsequent inspection period begins at the conclusion of the included SG inspection outage.

a)

After the first refueling outage following SG installation, inspect 100%

of the tubes during the next 144 effective full power months. This constitutes the first inspection period; b)

During the next 96 120 effective full power months, inspect 100% of the tubes. This constitutes the second and subsequent inspection periods.

c)

During the next 96 effective full power months, inspect 100% of the tubes. This constitutes the third inspection period; and d)

During the remaining life of the SGs, inspect 100% of the tubes every 72 effective full power months. This constitutes the fourth and subsequent inspection periods.

By using a common frequency of 96 EFPM for both the required SG inspections and the requirement to inspect 100 percent of the tubes, SG inspections will occur less frequently, but all tubes in the SG will be required to be inspected more frequently.

TS 5.6.6 The licensee proposed revising TS 5.6.6 to include a new paragraph i, which would state:

i.

Discuss trending of tube degradation over the inspection interval and provide comparison of the prior operational assessment degradation projections to the as-found condition.

3.0 TECHNICAL EVALUATION

3.1 Evaluation of Proposed Changes to TS 5.5.7 The NRC staff evaluation of the proposed TS changes focuses on the potential for these changes to affect SG tube integrity, since maintaining SG tube integrity is a current TS requirement that plays a key role in protecting the publics health and safety. In particular, the evaluation assesses whether the technical justification in Reference 1 demonstrates that the structural integrity performance criterion (SIPC) and accident-induced leakage performance criterion (AILPC) will continue to be met with the revised inspection intervals proposed in Reference 1. These tube integrity criteria are defined in TS 5.5.7.b.

As noted previously in Section 2.1.2, the only degradation mechanisms detected in the Sequoyah, Unit 1, SGs are tube wear from interaction with anti-vibration bars and advanced tube support grids, and since being placed in-service in 2003, only tube wear from anti-vibration bars has resulted in tubes being plugged. This operating experience aligns with industry experience at similar units that have SGs with Alloy 690TT tubing, where tube wear from tubing support structures is the predominate wear mechanism in these SGs.

In the operational assessment performed after the most recent in-service inspections during 1R21, the anti-vibration bar and advanced tube support grid wear mechanisms were evaluated as existing mechanisms, while wear from foreign objects was included as a potential mechanism.

The arithmetic method was implemented for the operational assessment during the 1R15, 1R18, and 1R21 outages. This is the most conservative of the methods described in Reference 9. In support of the proposed license amendment, the operational assessment performed in 1R21 was revised (Reference 2) using the Monte Carlo method, which is another method of analysis contained in Reference 9. The Monte Carlo analysis is a statistical method that uses random sampling from parameter distributions to determine the probability of burst and leakage at a future point in time. The Monte Carlo method uses a beginning-of-cycle flaw size, non-destructive examination flaw size measurement uncertainties, flaw growth rate uncertainties, material property uncertainties, and burst equation relational uncertainties to determine whether the probability of burst and leakage will meet the SIPC and AILPC of the plant TSs with a probability of 0.95 at a confidence level of 50 percent. The Monte Carlo method was applied to the largest anti-vibration bar wear indication returned to service, to the largest advanced tube support grids wear indication returned to service, and to the most limiting known foreign objects remaining in the SGs.

3.1.1 Evaluation of Existing Tube Degradation Mechanisms Wear at Anti-Vibration Bars Wear at anti-vibration bars has occurred in all four of the Sequoyah, Unit 1, SGs and has resulted in plugging 12 tubes in SG 1 and two tubes in SG 3. In the most recent inspections in 1R21, there were indications of anti-vibration bar wear in each SG, but only one tube was plugged in SG 1. The deepest wear indication returned to service was 28 percent through-wall.

To project the maximum through-wall depth at 1R26, the licensee applied a growth rate distribution based on the SG with the most limiting anti-vibration bar growth, which resulted in a maximum projected depth of 54.4 percent through-wall at 1R26. This maximum projected end-of-cycle depth met the structural limit. The structural limit is based on the limiting TS criterion of three times the normal operating pressure differential and includes material and burst pressure equation uncertainties. Since the maximum projected end-of-cycle depth met the structural limit, the licensee concluded the SIPC and AILPC would be met for anti-vibration bar wear until the next inspection in 1R26.

Wear at Advanced Tube Support Grids No tubes have been plugged in the Sequoyah, Unit 1, SGs due to wear at advanced tube support grids, but this mechanism was first detected in 1R18 and again seen in 1R21. The deepest wear indication returned to service after 1R21 was 22 percent through-wall.

A growth rate of 4.17 percent through-wall per effective full power year, which was the largest growth rate observed during Cycles 19, 20, and 21, was assumed. The projected 1R26 depth of 53.9 percent through-wall was below the structural limit; therefore, the licensee concluded the SIPC and AILPC would be met for advanced tube support grid wear until the next inspection in 1R26.

Evaluation Summary for Wear at Anti-Vibration Bars and Advanced Tube Support Grids Wear at these locations in the SGs has been effectively managed for many cycles without challenging tube integrity. Only 14 tubes have been plugged due to anti-vibration bar wear, and no tubes have been plugged due to advanced tube support grid wear. Wear at support structures is readily detected with standard eddy current examination techniques, and wear sizing errors are considered in the projection of existing flaws until 1R26. Due to the small number of wear locations at Sequoyah, Unit 1, wear projections based on two different operating intervals were compared for each of the four SGs, and the more limiting wear projection was used in their analysis, which showed that the projections of 1R26 through-wall depths meet the SIPC with margin. The NRC staff found the determination of beginning-of-cycle flaw depth and growth rates acceptable because it is based on industry guidelines and conservative assumptions. For flaws of this type, for pressure loading only, satisfying the SIPC demonstrates that the AILPC will also be satisfied since the limiting accident induced pressure differentials are much less than three times the normal operating pressure differential. Therefore, both SIPC and AILPC are satisfied. Based on the preceding discussion, the NRC staff finds that the licensees evaluation of tube wear at anti-vibration bars and advanced tube support grids to be acceptable.

Foreign Object Wear Sequoyah, Unit 1 has not reported any tube wear from foreign objects, but some small foreign objects have been retrieved from the SGs during refueling outages. As noted in Reference 1, the Sequoyah, Unit 1, SGs contain spray-can nozzles mounted to the top of the feedring.

These spray-can nozzles have many small diameter holes drilled in them that act as foreign object strainers, thereby limiting the potential for foreign objects to be introduced into the SGs.

The licensee performed a tube wear rate analysis as part of the operational assessment and concluded that at least six fuel cycles (9 effective full power years) of operation would accrue before the identified objects with the greatest potential to cause actual tube wear could potentially exceed the tube integrity performance criteria.

The NRC staff finds the licensees analysis of foreign object wear reasonable based on the use of the known population of foreign objects in the SGs, previous operating experience, and an SG design (foreign object strainers at the feed ring) that inherently limits introduction of foreign objects into the Sequoyah, Unit 1, SGs. The NRC staff also acknowledges that predicting future loose part generation is not possible because past fleet-wide operating experience has shown that new loose part generation, transport to the SG tube bundle, and interactions with the tubes cannot be reliably predicted. However, licensees can reduce the probability of loose parts by maintaining robust foreign material exclusion programs and applying lessons learned from previous industry operating experience with loose parts. Licensees in general, including TVA at Sequoyah, Unit 1, have demonstrated the ability to conservatively manage loose parts once they are detected by eddy current examinations or by secondary-side foreign object search and retrieval inspections. If unanticipated aggressive tube wear from new loose parts should occur in a Sequoyah, Unit 1, SG, operating experience has shown that a primary-to-secondary leak will probably occur, rather than a loss of tube integrity. In the event of a primary-to-secondary leak, the NRC staff will interact with the licensee in accordance with established procedures in Inspection Manual Chapter 0327, Steam Generator Tube Primary-to-Secondary Leakage, dated January 1, 2019 (Reference 10), to confirm the licensees conservative decision making.

3.1.2 Evaluation of Potential Tube Degradation Mechanisms The operational assessment performed following 1R21 did not include any stress corrosion cracking mechanisms as potential mechanisms, as operational assessment projections are only performed for existing degradation mechanisms, in accordance with the guidance provided in Reference 9. The NRC staff notes that while the licensee did not assume any stress corrosion cracking mechanisms as a potential in the operational assessment of the Alloy 690TT SG tubing, the licensee is required by TS 5.5.7.d to perform a degradation assessment prior to each SG inspection and to perform inspections with inspection methods that are capable of detecting flaws of any type that may be present along the length of the tube. This technical specification requirement ensures that each SG inspection will look for all types of degradation that may be present, whether they are existing or potential.

Although no form of stress corrosion cracking has been detected in the Sequoyah, Unit 1, SGs, the licensee is proposing to add a requirement to the Unit 1 TSs to perform periodic eddy current examinations with probes that are equivalent to or better than array probe technology.

Specifically, the proposed new wording (underlined) of TS 5.5.7.d.2 would state:

After the first refueling outage following SG installation, inspect each SG at least every 96 effective full power months. Tube inspections shall be performed using equivalent to or better than array probe technology. For regions where a tube inspection with array probe technology is not possible (such as due to dimensional constraints or tube specific conditions), the tube inspection techniques applied shall be capable of detecting all forms of existing and potential degradation in that region.

The NRC staff notes that the enhanced detection achieved by inspection with advanced probes could reasonably be expected to adequately offset the increased operational time between inspections, by providing a more accurate assessment of the current tube condition. The NRC staff believes that such inspections with advanced probes are an important element of an inspection program supporting an increased interval between inspections. Regardless of the specific tubing alloy in a steam generator, detection of existing loose parts is enhanced by using advanced probes, such as the combination bobbin and array coil probe or other equivalent (or better) probes.

Evaluation Summary for Potential Degradation Mechanisms The NRC staff reviewed the licensees evaluation of potential degradation mechanisms and compared them to the SG tube integrity criteria contained in the Sequoyah, Unit 1, TSs. The NRC staff considers the probabilistic evaluation assumptions to be acceptable for Sequoyah, Unit 1, because they were based on plant operating experience, bounding lengths and depths were assumed, and appropriate growth rates and uncertainties were used. The calculated probability of burst for each potential mechanism considered satisfied the SIPC margin requirements until the next inspection, and the AILPC was also satisfied until 1R26. Therefore, the NRC staff concludes there is reasonable assurance that both the tube structural integrity and leakage integrity performance criteria will be met for all tubes until 1R26 (i.e., within 96 EFPM of the last inspection), and will continue to be met during the revised inspection interval period of 96 EFPM through the new inspection requirement to use advanced probes.

3.1.3 Summary of Evaluation of Proposed Changes to TS 5.5.7 Based on the information submitted, the NRC staff finds that the licensee has demonstrated that there is reasonable assurance that the structural and leakage integrity of the Sequoyah, Unit 1, SGs will be maintained during the revised inspection interval of 96 EFPM, as proposed in Reference 1. Therefore, the NRC staff finds that the licensees proposed changes to TS 5.5.7 are consistent with the requirements of 10 CFR 50.36(c)(5) and, therefore, acceptable.

3.2 Evaluation of Proposed Changes to TS 5.6.6 The addition of a reporting requirement to the Sequoyah, Unit 1, TS 5.6.6, will help trend tube degradation over the inspection interval and provide a comparison of the prior operational assessment degradation projections to the as-found condition at the next inspection. Therefore, the NRC staff finds that the licensees proposed changes to TS 5.6.6 are consistent with the requirements of 10 CFR 50.36(c)(5) and, therefore, acceptable.

4.0 STATE CONSULTATION

In accordance with the Commissions regulations, the Tennessee State official was notified of the proposed issuance of the amendment on November 17, 2020. The State official had no comments.

5.0 ENVIRONMENTAL CONSIDERATION

The amendment changes a requirement with respect to installation or use of a facility component located within the restricted area as defined in 10 CFR Part 20 or changes an inspection or a surveillance requirement. The NRC staff has determined that the amendment involves no significant increase in the amounts, and no significant change in the types, of any effluents that may be released offsite, and that there is no significant increase in individual or cumulative occupational radiation exposure. The Commission has previously issued a proposed finding that the amendment involves no significant hazards consideration, and there has been no public comment on such finding published in the Federal Register on April 7, 2020 (85 FR 19511). Accordingly, the amendment meets the eligibility criteria for categorical exclusion set forth in 10 CFR 51.22(c)(9). Pursuant to 10 CFR 51.22(b), no environmental impact statement or environmental assessment need be prepared in connection with the issuance of the amendment.

6.0 CONCLUSION

The Commission has concluded, based on the considerations discussed above, that: (1) there is reasonable assurance that the health and safety of the public will not be endangered by operation in the proposed manner, (2) there is reasonable assurance that such activities will be conducted in compliance with the Commissions regulations, and (3) the issuance of the amendment will not be inimical to the common defense and security or to the health and safety of the public.

7.0 REFERENCES

1.

Sequoyah Nuclear Plant Unit 1 - Application to Revise Sequoyah Nuclear Plant (SQN)

Unit 1, Technical Specifications for Steam Generator Tube Inspection Frequency (SQN TS-20-01) dated February 24, 2020 (ADAMS Accession No. ML20056C857).

2.

Sequoyah Nuclear Plant Unit 1 - Response to Request for Additional Information Regarding Application to Revise Sequoyah Nuclear Plant (SQN) Unit 1, Technical Specifications for Steam Generator Tube Inspection Frequency (SQN-TS-20-01) dated September 23, 2020 (ADAMS Accession No. ML20267A525).

3.

TVA letter to NRC, Sequoyah Nuclear Plant (SQN) - Unit 1 Cycle 13 (U1C13) 12-Month Steam Generator Inspection Report, dated October 20, 2005 (ADAMS Accession No ML053050386).

4.

TVA letter to NRC, Sequoyah Nuclear Plant (SQN) - Unit 1 Cycle 15 (U1C15) 180-Day Steam Generator (SG) Inspection Report, dated April 23, 2008 (ADAMS Accession No ML081290185).

5.

TVA letter to NRC, Sequoyah Nuclear Plant (SQN) - Unit 1 Steam Generator Tube Inspection Information, Response to Request for Additional Information (RAI), dated August 15, 2008 (ADAMS Accession No ML082320482).

6.

TVA letter to NRC, Unit 1 Cycle 18 - 180-Day Steam Generator Inspection Report, dated December 17, 2012 (ADAMS Accession No ML12359A037).

7.

NRR E-mail Capture - RE: Sequoyah Unit 1 2012 SG ISI Report (TAC MF0387), dated May 13, 2013 (ADAMS Accession No ML13235A138).

8.

TVA letter to NRC, Unit 1 Cycle 21 - 180-Day Steam Generator Tube Inspection Report, dated February 13, 2017 (ADAMS Accession No ML17045A145).

9.

Electric Power Research Institute, Steam Generator Management Program: Steam Generator Integrity Assessment Guidelines, Revision 4, dated June 2016 (ADAMS Accession No. ML16208A272).

10.

Inspection Manual Chapter 0327 Steam Generator Tube Primary to Secondary Leakage, dated January 1, 2019 (ADAMS Accession No. ML18093B067).

Principal Contributor: A. Johnson, NRR Date: February 1, 2021

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